Oil and gas in Norway An introduction May 2022
ADVOKATFIRMAET BAHR AS
OIL AND GAS IN NORWAY | AN INTRODUCTION
Table of Contents
Page
1.
Introduction .................................................................................................................. 4
2.
Recent developments and key events on the NCS ..................................................................... 4
3.
The regulatory framework ................................................................................................. 7
4.
The main regulatory bodies and State participation in petroleum activities ...................................... 7
5.
Petroleum activity requires a production license ...................................................................... 7
6.
Licensing rounds ............................................................................................................. 7
7.
Plans for Development and Operation (PDO) ............................................................................ 8
8.
Joint Operating Agreements ............................................................................................... 8
9.
Licensees are required to provide a Parent Company Guarantee.................................................... 9
10.
Decommissioning liability .................................................................................................. 9
11.
The Norwegian Petroleum Tax System ................................................................................. 10
12.
Transactions and change of ownership ................................................................................ 11
13.
The government’s current approach to companies exiting the NCS ............................................... 12
OUR SERVICES...................................................................................................................... 12 RECENT MATTERS WITHIN THE OIL & GAS SECTOR................................................................................. 12 EDITORIAL COMMITTEE ........................................................................................................... 13
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1.
Introduction
reduced activity due to the COVID-19 pandemic, the Norwegian government enacted temporary targeted changes to Norway’s petroleum tax system, cfr. section 11 below.
Norway is a small player in the global crude market with production covering about two per cent of the global demand. However, Norway is the third largest exporter of natural gas in the world and Norway supplies about 25 per cent of the EU gas demand. Nearly all oil and gas produced on the Norwegian Continental Shelf (NCS) is exported, and combined, oil and gas equal about half of the total value of Norwegian export of goods. For this reason, oil and gas represent the most important export commodities for the Norwegian economy. Government income is secured by taxation and direct participation in the petroleum activities.
On 24 February 2022, Russia began a full-scale invasion of Ukraine. The invasion has major consequences for the energy market, as Russia is the world’s third largest exporter of oil and the world’s second largest exporter of gas. EU relies on Russia for around 40% of its natural gas and 27% of its oil consumption. As a response to the invasion, EU, USA and several other countries, including Norway, have adopted sanctions against Russia. The sanctions include, amongst others, that USA banned import of Russian oil and gas, that the Norwegian government decided to freeze the Norwegian Oil Fund’s investments in Russia, and that the Norwegian Ministry of Energy and Petroleum communicated that production licenses on the NCS would not be awarded to Russian companies. It has also led to the EU proposing an outline of a plan to make Europe independent from Russian fossil fuels well before 2030, starting with gas. Consequently, the oil and gas prices have risen dramatically. At this point, the oil price is at its highest since the financial crisis in 2008, and the price of natural gas in Europe has hit an all-time high. To achieve independence from Russian fossil fuels, several European countries and the EU have urged Norway to maintain and increase the supply of oil and gas, to which Norway has responded positively. As Norway already is a large supplier of oil and gas, and the demand for fossil fuels is increasing, Norway is likely to play an important part in securing energy supply to Europe. Analytics have predicted that the Norwegian petroleum revenues will increase sixfold during 2022. Independent from the above, the Government has also presented a bill to change the petroleum tax into a cash-based system. If the changes are adopted by the Parliament, the petroleum companies will be entitled to immediately deduct investment costs with a tax value of 71.8%. The changes are expected to take effect from 1 January 2022, see section 11 below.
Macroeconomic indicators for the petroleum sector, 1971-2022:
(Source: Statistics Norway (National accounts), Ministry of Finance (The National Budget 2022))
Since production started in 1971, oil and gas have been produced from a total of 119 fields on the NCS. At the end of 2021, 94 fields were in production: 71 in the North Sea, 21 in the Norwegian Sea and two in the Barents Sea. In 2021, 4 new fields were set in production. Six fields are currently under development. Many of the producing fields are ageing, but some of them still have substantial remaining reserves. Petroleum resources on the NCS have been estimated to 15.8 billion standard cubic metres of oil equivalents. Only around 50 per cent of the total discovered and estimated undiscovered petroleum resources have so far been produced and sold. 2.
Recent developments and key events on the NCS
High activity level
From COVID-19 and production cuts to Russia’s invasion of Ukraine and increased oil and gas production
In 2021, 8 PDOs were delivered to the Ministry of Energy and Petroleum and the PDO for Breidablikk was approved, as was the amended PDOs for Sleipner and Troll. Further, 4 new fields were set in production, being Martin Linge, Duva and Solveig in the North Sea, and
As in 2020, the energy market in 2021 was to a great extent influenced by the global COVID-19 pandemic and falling oil prices. In an effort to maintain oil and gas investments during a period of falling oil prices and -4-
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Ærfugl Nord in the Norwegian Sea. In addition, Yme restarted production after completing a redevelopment of the field.
adopted the budget for the Ministry of Petroleum and Energy for 2021, which included approval of funding for “Longship”, a full-chain carbon capture, transportation, and storage project, including the project Northern Lights. Northern Lights is a project which intends to transport captured and liquified CO2 by ship from the Eastern part to the Western part of Norway, and thereafter by pipeline to an offshore storage location subsea in the North Sea for permanent storage.
The exploration activity on the NCS was higher in 2021 than in 2020, but still a little lower compared to 2018 and 2019. In 2021, 40 exploration wells were spudded, and 20 discoveries were made on the NCS. In the 2021 APA round awarded in January 2022, 28 companies were awarded a total of 53 licenses, consisting of 28 in the North Sea, 20 in the Norwegian Sea and 5 in the Barents Sea. 17 of the production licenses are additional acreage to existing production licenses.
On 9 March 2021, the Ministry of Petroleum and Energy approved the development plan for the Northern Lights project, the storage part of the Longship carbon capture and storage project. Further, in September 2021, the Ministry announced two relevant areas in the North Sea and the Barents Sea for injection and storage of CO2 on NCS. In December 2021, the Ministry of Energy and Petroleum stated that they had received applications from five companies, this being A/S Norske Shell, Equinor ASA, Horisont Energi AS, Northern Lights JV DA and Vår Energi AS. The areas are expected to be awarded during the first half of 2022.
In November 2020, the Norwegian government announced the 25th licensing round on the NCS, comprising one area in the Norwegian sea and 8 areas in the Barents Sea. On 23 June 2021, production licenses were awarded to Norske Shell, Equinor, Idemitsu Petroleum Norge, Ineos E&P Norge, Lundin, OMV (Norge) and Vår Energi, distributed on one area in the Norwegian sea and three areas in the Barents Sea. It was determined in the National Budget 2022 that the 26th licensing round on the NCS will not be held in 2022. Increased focus on renewables and climate As in other areas of society, there has been an increased focus on climate change and reduction in greenhouse gas emissions in the oil and gas industry in recent years, with several key changes and initiatives in process. The Climate Change Act adopted in 2017 introduced a target reduction in greenhouse gas emissions by at least 40 per cent by 2030 from 1990 levels. In January 2020, similar target reductions associated with production of oil and gas on the NCS was made by a sector wide initiative supported by the wider Norwegian oil and gas industry, setting a target of 40 per cent reduction in greenhouse gas emissions within 2030 compared to 2005 levels and a reduction to near zero in 2050. In February 2020, the Norwegian government presented updated goals to the UN in accordance with the Paris agreement, with the aim of reducing greenhouse gas emissions by 50-55 per cent (compared to 1990 levels) by 2030. The long-term goal is to reduce emissions by 90-95 per cent by 2050.
(Source: Illustration CCUS, Gassnova, www.norskpetroleum.no)
There has also been an increased focus on electrification of the installations on the NCS. Today, the fields Troll, Gjøa, Ormen Lange, Valhall, Goliat and Johan Sverdrup are supplied directly with onshore electricity. In addition, Vega is supplied with onshore electricity through Gjøa, and Hod through Valhall. Further, plans exist to supply several other fields in the coming years. The plans currently adopted are expected to reduce CO2 emissions with 3.2 million tons per year in 2023. Other plans are under development, and if adopted; the CO2 emissions may be reduced with a total of 4.9 million
In recent years, there has been an increased focus on carbon capture, utilisation and storage (CCUS), including by assessing the use of offshore oil and gas reservoirs for storage of carbon. On 14 December 2020, the Parliament -5-
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tons, which would entail a reduction of nearly 40 per cent of the total emissions from the petroleum industry in 2019.
he electricity grid is essential for electrification and phasing out fossil fuels. A trend in recent years has also been for oil and gas companies to transition into more diversified and “greener” energy companies by acquiring or developing renewable energy assets. This trend may continue in coming years.
In 2019, the Ministry received the development plans for the Hywind Tampen floating offshore wind farms. The aim for the project is to replace one third of the gasfired power with renewable wind power for the Snorre and Gullfaks fields. The proposed project plan was approved by the Ministry of Petroleum and Energy on 8 April 2020.
The “climate lawsuit” On 22 December 2020, the Norwegian Supreme Court, sitting in plenary, passed its judgement in the “climate lawsuit” raised by Nature and Youth and Greenpeace Nordic against the Norwegian State regarding the validity of the decision to grant production licenses in the Barents Sea in the 23rd licensing round. The appellants argued that the Royal Decree granting the production licenses was invalid, claiming that it was in breach of the environmental protection provision and certain other provisions of the Norwegian Constitution and the European Convention on Human Rights (ECHR), in addition to suffering from procedural errors.
On 1 January 2021, the areas Utsira Nord and Sørlige Nordsjø II were opened for applications to develop offshore wind farms, which may also contribute to the supply of electricity to petroleum installations. On 9 February 2022, the government announced its intention to hold an auction for 1.5 GW on Sørlige Nordsjø II during 2022 and initiated the process to identify additional areas for offshore wind development on the NCS. The model for awarding acreage will remain auction-based, and the government has commenced the work to determine the auction framework. The government announced that the first 1.5 GW of Sørlige Nordsjø II and Utsira Nord shall be connected to the mainland of Norway (i.e., for the time being not to be developed as a hybrid project connected to Europe or UK), however, the government will consider grid connection for the second phase of Sørlige Nordsjø II. A study will be carried out by the Norwegian Water Resource and Energy Directorate (NVE) and Statnett, and is, according to the Minister of Petroleum and Energy, expected by 1 October 2022.
The Supreme Court unanimously rejected the appeal on the constitutional and ECHR issues, stating that it is up to the Parliament and government to decide by which means environmental goals are to be pursued. On the procedural question, a majority vote of eleven justices rejected the appeal, while a minority of four justices voted in favour of the appellants based on deficiencies related to the impact analysis prior to granting the production licenses. Following the Supreme Court ruling, the Ministry of Energy and Petroleum has in its supplementary White Paper on Energy Policy presented in April 2022 announced that the Ministry will assess the climate impact of emissions from production and produced petroleum (Scope 3 emissions) as part of the process to approve new field developments. In addition, new development plans presented for approval need to include an assessment of the financial climate risk associated with the development. This means that the robustness analysis of the project economy must include expected profitability in a market/policy environment compliant with the targets of the Paris Agreement. Since projects approved over the last years have seen profitability at USD 30/bbl and expected amortization of investments over a few years (ca. 3.5 years), the analysis is not expected to be decisive for whether the project is profitable but may be relevant to the level of super
In January 2021, the Norwegian government presented a white paper (Meld. St. 13 (2020-2021)) on a climate plan for 2021-2030, stating inter alia that the total costs for CO2-emissions will be gradually increased to NOK 2,000 per tonne in 2030. This will also affect the oil and gas industry and further incentivise electrification and other low carbon solutions on the NCS. In June 2021, the government presented a white paper (Meld. St. 36 (2020-2021) stating that Norway’s position as an energy nation will be further developed through investments in new industries, such as hydrogen and offshore wind, strengthening of the electricity grid and a futureoriented oil and gas industry with low emissions. The white paper is based on and continues the government’s climate plan and illustrates how renewable energy and -6-
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profit that may be expected from the development.
transportation system on the NCS. In 2021, the responsibility for managing the State’s direct and indirect participation in the petroleum activities through SDFI/Petoro and Equinor was transferred from the Ministry of Energy and Petroleum to the Ministry of Trade, Industry and Fisheries – who also manage the State’s ownership interest in other entities such as DNB, Norsk Hydro and Yara.
In June 2021, the climate activists brought their case against the Norwegian State to the European Court of Human Rights. 3.
The regulatory framework
The Norwegian Petroleum Act of 1996 (the Petroleum Act) sets out the main regulatory framework for petroleum activities on the NCS. The Petroleum Act is based on the principle that all petroleum deposits on the NCS belong to the Norwegian State, and that the State can grant production licenses allowing others to explore for and produce petroleum. Governmental control is further exercised through the requirement of approvals in all phases of petroleum activities, from gathering of seismic data and exploration drilling, to development, operation and decommissioning of oil installations, as well as approval for the transfer of already granted production licenses. The Petroleum Act is supplemented by other legislations specifically relating to petroleum activities, such as the Petroleum Tax Act of 1975, as well as general legislation relevant to petroleum activities such as the Working Environment Act of 2005 and the Pollution and Waste Act of 1981.
5.
Companies wishing to engage in petroleum activities on the NCS must hold a production license, providing rights to engage in petroleum activities within a defined geographical area. Production licenses can be awarded to existing oil companies on the NCS, or to new entrants that are prequalified to hold such licenses. The general policy is that petroleum activities must be carried out by entities that are able to contribute to the Norwegian petroleum industry beyond just financial participation, and that the activities are carried out in an efficient, competent, and responsible manner. Therefore, license awards and prequalification require that the company can demonstrate sufficient technical, financial and Health, Safety and Environment (HSE) resources. The prequalification procedure for new entrants typically takes up to half a year. Guidelines for pre-qualification are found on the web page of the Petroleum Directorate.
In addition, there is a significant volume of secondary regulations concerning different aspects for petroleum activities. 4.
Petroleum activity requires a production license
The main regulatory bodies and State participation in petroleum activities
6.
Licensing rounds
Production licenses are awarded through licensing rounds. There are two different kinds of licensing rounds on the NCS. There is an annual system of Awards in Predefined Areas (APA) in mature parts of the NCS. The APA system ensures that very large areas close to existing and planned infrastructure are available to the industry. In addition to the APA system, there is a system of ordinary licensing rounds which is normally held every second year. These rounds focus on frontier areas on the shelf that are less explored and with less existing infrastructure built.
The main regulatory body is the Ministry of Petroleum and Energy, which has authority over most parts of the Petroleum Act including ownership regulations and licensing rounds. Some of these functions are delegated to the Petroleum Directorate. Major development projects and issues of fundamental importance must be approved by the Norwegian Parliament. The Ministry of Finance has authority for petroleum tax matters. The Petroleum Safety Authority is responsible for safety and HSE matters. The Norwegian State has substantial holdings in production licences on the NCS through the State’s Direct Financial Interest (SDFI). The formal licensee for the SDFI assets is Petoro AS, a company wholly owned by the State. In addition, the State participates through its ownership interests in Equinor ASA (formerly Statoil) and Gassco AS. The latter is a company wholly owned by the State which is the operator of the comprehensive gas
The Ministry of Petroleum and Energy awards production licenses based on the applications submitted. Relevant, objective, non-discriminatory and announced criteria form the basis for these awards. Applicants can apply individually or as a group. New production licenses are awarded to a group of companies, that each will hold a participating interest -7-
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in the license. The license grants the participants exclusive rights to surveys, exploration drilling and production of petroleum within the geographical area covered by the license. The licensees become the owners of the petroleum that is produced.
economical profitability of the development based on future oil prices in a market/revised policy scenario compliant with the goals of the Paris Agreement. Furthermore, following up on the Supreme Court ruling in 2020 in the “climate lawsuit”, the Ministry will as part of its approval process include an assessment of the climate effect of emissions from both production and petroleum produced from the field.
Production licenses are valid for an initial period (exploration period) that can last for up to ten years. During this period, a work commitment programme must be carried out in the form of e.g., geological/geophysical preliminary work and/or exploration drilling. If all the licensees agree, the production license can be relinquished when the work commitment has been fulfilled. If the licensees want to continue the work in the production licence, the license will enter the extension period, which is the period for development and operation.
The petroleum activities shall be conducted in a prudent manner to ensure that a high level of HSE can be maintained and developed throughout all phases, in line with the continuous technological and organisational development. The licensees are responsible for pollution without regard for fault. This is referred to as strict liability. 8.
The production licenses are registered in the Petroleum Registry which is an official and publicly available register that among other records ownership and encumbrances. Production licenses can be mortgaged upon application and approval from the Ministry of Petroleum and Energy. 7.
Joint Operating Agreements
The license holders form a joint venture that is responsible for the petroleum activities within the license area. The license group will enter into a Joint Operating Agreement (JOA) which regulates the rights and obligations for the joint venture within the specific license. The JOAs are based on a standard format that the Ministry of Petroleum and Energy requires all license holders to use. The Ministry nominates one of the participants in the license as the operator, which will be responsible for the operational activities authorised by the license. Major decisions are made by the management committee where all license holders are represented and have voting rights according to voting rules set out in the license terms. Normally, a decision is made by the management committee when at least two of the participants that jointly represent at least 50 per cent of the participating interest vote in favour of a proposal. The participants in the license have joint and several liability for the obligations and liabilities arising out of the license.
Plans for Development and Operation (PDO)
If the licensees find that it is commercially viable to develop a discovered field, they are required to do so in a prudent manner. The licensees are responsible for the development of new projects, but the development is subject to approval from the authorities. The approval is provided on the background of a Plan for Development and Operation (PDO) submitted to the Ministry for approval. Large and/or important projects are presented to Parliament before the Ministry’s approval. An important part of the PDO is an impact assessment which is submitted for consultation to various bodies that could be affected by the specific development. The impact assessment shows how the development is expected to affect the environment, fisheries, and society in general. The processing of this assessment and the PDO itself ensures that the projects are prudent in terms of resource management, and that the consequences for other public interests are acceptable. The impact assessment is compulsory unless the licensees can document that the PDO is covered by a relevant existing impact assessment. The Ministry has proposed that the impact assessment shall include an assessment of the financial climate risks associated with the development. This entails an assessment of the -8-
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9.
Licensees are required to provide a Parent Company Guarantee
the particular claim for unlawfully received tax refund of the exploration expenses. Although the judgement gives some clarification as to the extent of the PCG, a question is how the government will react with respect to this going forward.
The Petroleum Act section 10-7 gives the Ministry of Petroleum and Energy the right, at any time, to demand adequate security for holders of production licenses on the NCS. The authority pursuant to section 10-7 is quite wide with regard to timing and the nature of the security that can be required. However, in practice the Ministry requires licensees to provide an unlimited Parent Company Guarantee (PCG) for the benefit of the Norwegian State to secure all obligations in relation to the petroleum activities. The format and wording of the parent company guarantee is based on a standard template. This standard form is non-negotiable and is kept in a brief format. So far there have been no instances where the guarantee has been used in practice, and there are therefore several issues where the interpretation is unclear. For instance, it is debated whether other participants in a license can draw on the guarantee if another partner in the license defaults on its obligations.
10. Decommissioning liability
As a main rule, the Petroleum Act requires licensees to submit a decommissioning plan to the Ministry of Petroleum and Energy two to five years before the licence expires or is relinquished, or before the use of a facility ceases. The cessation plan must have two main parts: an impact assessment and a disposal section. The impact assessment provides an overview of the expected consequences of the disposal for the environment and other factors. The disposal part must include proposals for how cessation of petroleum activities on a field can be accomplished. In addition to the Petroleum Act, the Oslo Paris Convention for the protection of the marine environment of the North- East Atlantic (OSPAR) also governs disposal of facilities. As a general principle under the OSPAR convention, facilities cannot be abandoned on-site.
The main policy is that the Ministry will require that the parent company guarantee is provided by the ultimate parent company of the licensee. A company is considered a parent company if the company, directly and/or indirectly, owns or controls more than 50 per cent of the licensee. Thus, a company owning and/or controlling bona fide less than 50 per cent will normally not be required to issue a PCG. There are examples where the parent company guarantee has been issued by entities within a group that is not the ultimate parent company. For corporate transactions, the current policy of the Ministry is to return parent company guarantees if a shareholder ceases to have more than 50 per cent of the shares in the licensee.
It follows from the Petroleum Act that a seller of a participating interest in a production license will remain secondary liable for decommissioning costs. The secondary liability applies to the seller’s share of installations existing at the time of the transaction and is a financial obligation to pay the (after tax) cost of the decommissioning if the buyer of the participating license fails to meet its obligations. In order to protect the seller from such liability it is not uncommon to enter into decommissioning security agreements between the buyer and the seller, depending on the financial solidity of the parties and the amount of decommissioning obligations. In a corporate transaction structured as a sale of a controlling interest in a Norwegian E&P entity, practise has now been established whereby the Ministry of Petroleum typically require that the ultimate selling
In March 2020, the Supreme Court rendered its judgement in a case where the question was whether or not the parent company guarantee covers tax claims incurred by the licensee. A company had unlawfully received refund for the tax value of its exploration expenses. The company was unable to repay the refund. Thus, the State, represented by the tax authorities, filed a claim against the company’s parent company, upholding that the latter had to cover the repayment expenses under the parent company guarantee. Contrary to the Court of Appeals, the Supreme Court held that the parent company guarantee did not cover -9-
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parent company issue a parent company guarantee to the State establishing a comparable secondary liability for decommissioning obligations of the target entity – see more on this in section 13 below.
The licensee will be entitled to tax deductions with regard to exploration and production costs (running expenses, depreciations and uplift) and transportation costs (tariff payments). Financial costs are allocated between the 22 per cent tax base and the 78 per cent tax base. Losses and unused uplift may be carried forward indefinitely with an interest. The calculated interest is added at the end of each year. Companies not being in a tax position may annually apply for a refund of the tax value of exploration expenses (save financial costs). Also, there is a system of repayment of the tax value of accumulated tax losses carried forward and unused uplift upon cessation of petroleum activities on the NCS.
There is currently no practice or requirement for general decommissioning security arrangements internally between the partners in a license. 11. The Norwegian Petroleum Tax System The petroleum resources belong to the Norwegian State and the State secures its revenues through taxation, direct participation in the licenses and as a shareholder in Equinor. Norway has no additional production sharing or royalty schemes but imposes fees on emission of CO2 and NOX.
Norm prices can be imposed when calculating taxable income from the sale of produced petroleum. The Petroleum Price Council (PPR) determines the norm price. The Council receives information from and meets with companies before setting the final norm price. This norm price system applies to certain grades of crude oil and NGL. For gas, the actual sales price is used as the tax basis. However, related party transactions may be adjusted by the tax authorities if the gas prices are not in line with the arm’s length principle.
For companies participating in production and pipeline transportation of petroleum on the NCS, there are two, partially overlapping, income tax regimes: ordinary income tax imposed by the general rules in the General Tax Act and the special petroleum tax on income imposed by the Petroleum Tax Act due to the extraordinary profit associated with recovering the petroleum resources. The total marginal income tax rate for E&P activities on the NCS is 78 per cent, consisting of a 22 per cent general income tax and a 56 per cent special petroleum tax to the State levied on income generated by exploitation, treatment or pipeline transportation of petroleum. The petroleum tax applies on a corporation net profit level, not on a ring-fenced basis. Losses generated by other activities may as a general rule not to be set off against assessed income for special tax purposes (56 per cent) and there are limitations on the right to set off other losses against the general tax base (22 per cent).
In 2020, provisional tax changes were made to stimulate investments in the petroleum sector. A key element is that investments booked in 2020 and 2021 are immediately tax deductible in the tax base for special tax (56 per cent tax rate), in addition to that the uplift is increased to 24 per cent in the year of investment. Such tax treatment will also comprise investments made pursuant to (A) a PDO/PIO filed before 1 January 2023 and (B) approved by the Government after 12 May 2020, but before 1 January 2024 (but not investments made after the year of planned “first oil” as defined in the approved PDO/PIO).
Depreciation of production installations and offshore pipelines are permitted under a straight-line method at a rate of 16 2/3 per cent annually from the year in which the investments take place (tax value of 78 per cent), i.e., deprecation over 6 years. In addition to the depreciation allowance offered, an extra deduction (uplift) is allowed in the basis for special tax (tax value of 56 per cent) to shield normal return from special tax. An uplift of 5.2 per cent per year is thus granted in the special tax basis for a four-year period (from and including the investment year) for investments in production and pipeline facilities.
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Investments comprised by the provisional tax changes are capitalised and depreciated over 6 years in the ordinary tax base (22 per cent tax rate), as under the ordinary petroleum tax rules.
energy supply to Europe, this provision should be assessed in each individual transaction. Direct transfer of participating interests is subject to approval by the Ministry of Petroleum and Energy pursuant to the Petroleum Act. The same applies for share transactions which according to law “may provide decisive control of a licensee possessing a participating interest in a licence”.
Another key feature of the provisional tax changes is that the tax value of losses incurred in 2020 and 2021 (in both the ordinary tax base and in the special tax base (including the uplift of 24 per cent) will be refunded in cash by the state. The refund will be refunded in advance of the tax assessment on a running basis based on a preliminary estimate of the loss carried forward with a final settlement in Q4 following the income year.
In a letter from 2018, the Ministry gave guidance that the wording shall be interpreted very widely, and that approval may be required for transactions where the buyer does not even achieve negative control. Further, it stipulated that any uncertainty with respect to the applicability of the requirement must be discussed with the Ministry.
In April 2022, the Government published a bill addressing permanent amendments to the petroleum tax regime. A central change will be that investments are deductible with immediate effect in the special tax base as from the income year 2022. The uplift is repealed. Investments shall still be capitalised in the general tax base and, thus, depreciated over 6 years. The tax value of tax losses in the special tax base (but not the ordinary tax base) will, thus, be refunded on a continuous basis. Historical tax losses carried forward and unused uplift in the special tax regime (technically tax value of 71.8 per cent) will be refunded as a part of the tax assessment for the income year 2022. The new tax model will involve uncertainty for the full tax value of tax losses and decommissioning costs. Further, the petroleum companies will no longer be entitled to uplift, and, thus, end a long going discussion of the correct interest rate for calculating the tax value of future investment deductions.
Approval by the Ministry of Finance is also required for the same transactions for tax purposes. The main principle is that transactions should be tax natural. Hence, in asset transactions (direct transfer of participating interests) the tax basis of depreciation and uplift related to the assets are transferred to the buyer (tax continuity). Further, the consideration is not taxed as income for the seller and is, correspondingly, not deductible for the buyer. Losses and unused uplift carried forward will as a rule remain with the seller. Share transactions will normally not trigger Norwegian tax. Transactions can also trigger other regulatory approvals, such as approval from the Ministry of Petroleum and Energy for change of operatorship or approval to create pledges over the license interests. The Petroleum Safety Authority can also require that new applications are made with regard to HSE related permits if the transaction changes the basis for existing permits.
12. Transactions and change of ownership Participating interests in Norwegian petroleum licenses are transferrable, and there is a market for buying and selling such participating interests. As a general rule, the participating interests can be sold without the consent of the other license partners, provided that the compulsory work obligation set out in the license has been fulfilled. Prior to fulfilment of the work obligation the management committee of the license must give its consent to an assignment. There are normally no preemption rights for the other license partners pursuant to the JOAs, except for in some of the older licenses. The Norwegian State/Petoro has a right of pre-emption, but so far this has to our knowledge not been used in practice. In a scenario with increased focus on securing
It is a general principle that all petroleum activities within a group are conducted through one single legal entity. Therefore, if an existing company buys the shares of another company, the Ministry of Petroleum and Energy will require that the businesses are combined into one single legal entity. If the two companies are participants in the same licenses, the Ministry may also require that the voting rules are amended. If a contemplated transaction leads to a company acquiring 100 per cent ownership in a production license, the Ministry of Petroleum and Energy has in recent transactions set as a requirement for its approval - 11 -
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that the acquiring company divests a part of its participating interest in the relevant license. The deadline for selling down varies from up to a year for exploration assets, to having to sell down immediately for some producing assets. Further, the management committee’s leeway will be restricted until the divestment is completed.
that the new approach will raise debate about the tax treatment in general, including the availability of tax refunds upon cessation of petroleum activities and the risk that lower tax rates can increase the post-tax cost of decommissioning for the companies. *** Further information regarding Norwegian petroleum activities
13. The government’s current approach to companies exiting the NCS
(including unofficial translations of the model production license and JOA) can be found here:
Up until late 2017, it was possible to achieve a clean exit from the NCS by selling shares in a subsidiary that holds production licenses. For share transactions there was no secondary liability for decommissioning, since a share transaction does not imply a change of the legal entity holding the production license. It was also the government’s policy to return the parent company guarantee when the shares were sold. Examples of companies previously having achieved a clean exit from the NCS by selling the shares in the subsidiary, includes RWE, E.ON, Marathon, Svenska Petroleum, Premier Oil and BP.
https://www.norskpetroleum.no/en/ This site is run in cooperation by the Ministry of Petroleum and Energy and the Norwegian Petroleum Directorate.
OUR SERVICES BAHR’s legal team has vast experience of working closely with a number of major players on the Norwegian Continental Shelf. We have a thorough understanding of the legal framework governing the industry. We advise in large transactions and represent companies in legal disputes. We also assist in connection with major development projects. Furthermore, we have comprehensive experience within the regulatory field including extensive government relations. BAHR also has expertise in petroleum taxation, appeals and litigation of tax disputes. We represent several large oil companies in complex tax disputes before the tax assessment administration and the court.
As many of the international majors have already exited the NCS or have communicated that they intend to divest, a concern for the government has been whether the new entrants will be able to meet future decommissioning costs. This prompted the government to revisit the policy of granting companies a clean exit, and in November 2016 the Ministry of Petroleum and Energy sent a letter to the companies to address its new approach to such matters.
RECENT MATTERS WITHIN THE OIL & GAS SECTOR
The Ministry stated that for all future share transactions it would consider imposing as a new condition to approve the new owner that the selling shareholder undertakes to issue a new parent company guarantee where the seller remains secondary liable for existing decommissioning obligations. As from late 2017, the Ministry has implemented this as a requirement for approval of share transactions and has developed a standard template for the new guarantee that the seller must issue. As a result of this approach, share transactions and asset transactions are now treated more equally in terms of decommissioning obligations. Several questions arise relating to this approach which has yet to be resolved, inter alia whether a payment under the new guarantee should be calculated as an amount pre- or post-tax. It is also likely - 12 -
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Assisting Aker and Aker BP with the acquisition of Lundin Energy Norway.
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Assisting Sval Energi on several transactions, including the acquisition of Spirit Energy Norway AS’s key assets and the acquisition of and subsequent consolidation with Edison Norge AS.
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Assisting INEOS on the sale of the entire Norwegian E&P business to PGNiG Upstream Norway AS.
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Assisting Sval Energi AS with a wide range of key matters, including advising on transactions, contracts, employment and corporate law and other regulatory issues.
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Assisting with the sale and purchase of Sval’s interests in the gas transportation infrastructure Polarled and Gassled.
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Acting as counsel for HitecVision in an international oil and gas arbitration against Tullow Oil.
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Acting as counsel to OMV (Norge) AS in relation to a dispute arising out of a tie-in agreement on the Norwegian Continental Shelf.
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Acting as counsel for Sleipner Øst Unit in an appeal case against Karmøy municipality.
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Assisting underwriters in connection with the public offering and listing of Vår Energi ASA on Oslo Børs.
OIL AND GAS IN NORWAY | AN INTRODUCTION
EDITORIAL COMMITTEE For more information, please contact:
Stig K. Engelhart
Marius Pilgaard
D: +47 22 01 68 61
D: +47 22 01 68 34
M: +47 47 01 11 12
M: +47 90 68 82 47
E: skl@bahr.no
E: mapil@bahr.no
Trond Lingaas
Fanny Bjærke Estensen
D: +47 21 01 66 94
D: +47 21 00 00 50
M: +47 92 04 46 74
M: +47 91 12 11 57
E: troli@bahr.no
E: faest@bahr.no
This pamphlet contains information in summary form and is therefore intended for general guidance only. It is not intended to be relied upon as legal advice or be a substitute for detailed research or the exercise of professional judgement. Please refer to your advisors for specific advice. BAHR will not accept any responsibility for loss occasioned to any person acting or refraining from action as a result of any material in this newsletter.
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